Statement of Michael F. Mundaca Assistant Secretary (Tax Policy) Department of the Treasury Before Committee on Ways and Means April 14, 2010

April 14, 2010

(Archived Content)

TG - 640

Good morning Chairman Levin, Ranking Member Camp, and members of the Committee. Thank you for inviting me to testify before your Committee today. I appreciate the opportunity to discuss the energy proposals in the President's FY 2011 Budget.

Overview of the Administration's Environmental and Energy Policy

First, I will briefly discuss the Administration's environmental and energy policy in order to provide context for the energy proposals in the Budget.

The Obama Administration believes that our nation must build a new, clean energy economy, curb our dependence on fossil fuels, limit the emissions of greenhouse gases (GHGs), and make America more energy independent. It is no longer sufficient to address our nation's energy needs solely by finding more fossil fuels. Instead we must take dramatic steps towards becoming a clean energy economy. These include encouraging the use of, and investment in, clean energy infrastructure and energy efficient technologies.

The American Recovery and Reinvestment Act of 2009 (Recovery Act) took an important step in that direction by providing more than $80 billion for investment in clean energy technologies. In addition, the Administration recently announced new fuel economy standards that by 2016 will require automobile fleets to average 34.1 miles per gallon, and also achieve a combined reduction in carbon emissions from fuel economy improvements and EPA standards for automobile air conditioners equivalent to the reduction that would be achieved by a fuel economy of 35.5 miles per gallon. These new standards are expected to save 1.8 billion barrels of oil over the life of cars and trucks sold in the 2012-2016 model years and reduce carbon dioxide emissions by about 960 million metric tons over the lifetime of those vehicles, equivalent to taking 50 million cars and light trucks off the road in 2030. The Administration's Budget further promotes these objectives by investing in a variety of renewable sources of electricity generation, by investing to accelerate deployment of energy conservation measures, by providing support for the construction of new nuclear power plants, by advancing the development of carbon capture and storage technologies, and by providing Federal assistance for state-level programs related to clean energy and energy conservation. The President has recently established an Interagency Task Force on Carbon Capture and Storage. This task force will develop a plan to overcome the barriers to the widespread, cost-effective deployment of CCS within 10 years, with a goal of bringing 5 to 10 commercial demonstration projects online by 2016. The plan should explore incentives for commercial CCS adoption and address any financial, economic, technological, legal, institutional, social, or other barriers to deployment. The President has also called on Congress to invest in a new HomeStar program of rebates for consumers who make energy efficiency retrofits. Such a program will harness the power of the private sector to help drive consumers to make cost-saving investments in their homes.

In addition to direct investments in clean energy, the Administration's Budget proposes to enact and implement a comprehensive market-based policy that will reduce GHG emissions in the range of 17 percent below 2005 levels by 2020 and more than 80 percent by 2050. The policy will stem carbon pollution, help reduce our dependence on foreign oil, promote advanced industries and technology right here in the U.S., all while providing businesses the flexibility to find the least costly and most efficient ways of achieving GHG emission reductions. In addition, the policy will address the needs of vulnerable families, communities, and businesses in the course of the transition to a clean energy economy.

As part of a comprehensive energy strategy to move from an economy that runs on fossil fuels and foreign oil to one that relies on homegrown fuels and clean energy, the Obama Administration is also proposing to expand oil and gas development and exploration on the Outer Continental Shelf. The proposed expansion will enhance our nation's energy independence while protecting fisheries, tourism and places off the U.S. coast that are not appropriate for development.

Budget Proposals Relating to Energy

With this as background, let me turn to the tax-related proposals in our Budget relating to energy. More details on each proposal can be found in the appendix.

1. Repeal existing fossil fuel preferences

Current law provides a number of credits and deductions that are targeted towards certain oil, gas, and coal activities. These tax subsidies, which are not designed to correct an existing distortion or market failure, lead to an over allocation of resources to these industries and an under allocation of resources to other industries. This distortion in resource allocation results in inefficiency and generally reduced economic growth. Moreover, the tax subsidies for fossil fuels must ultimately be financed with taxes that result in underinvestment in other, potentially more productive, areas of the economy. In accordance with the President's agreement at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so that we can transition to a 21st century energy economy, the Budget proposes to repeal a number of tax preferences that are currently available for fossil fuels.

The following tax preferences for oil and gas activities are proposed to be repealed beginning in 2011:

The enhanced oil recovery credit . The credit is equal to 15 percent of the cost of certain tertiary oil recovery methods. The credit phases out when the price of oil exceeds a specified level and is completely phased out at current price levels. Eliminating this preference is projected to have no revenue effect because the price of oil is expected to remain above the phase-out range through 2020.
The credit for oil and gas produced from marginal wells . The credit is $3.00 per barrel of oil and $0.50 per 1,000 cubic feet of natural gas (adjusted for inflation since 2005) produced from certain low-production wells. The credit phases out when the prices of oil and natural gas exceed specified levels and is completely phased out at current price levels. Eliminating this preference is projected to have no revenue effect because the prices of oil and natural gas are expected to remain above the phase-out range through 2020.
Expensing of intangible drilling costs . This preference permits taxpayers to deduct drilling costs that would otherwise be included in an oil or gas property's depreciable or depletable basis. The Budget proposal would require these costs to be capitalized in accordance with the generally applicable rules. Eliminating this preference is projected to raise $7.8 billion in revenue through FY 2020.
The deduction for tertiary injectants . This preference permits taxpayers to deduct the cost of injectants that are used as part of a tertiary recovery method. The Budget proposal would eliminate this deduction. Repeal of the deduction is projected to raise $67 million through FY 2020.
Passive loss exemption for working interests in oil and gas properties . This preference exempts certain oil and gas activities from the generally applicable rule limiting the allowable losses and credits from activities in which a taxpayer does not materially participate. The Budget proposal would eliminate this exemption. Elimination of the exemption is projected to raise $180 million through FY 2020.
Percentage depletion for oil and gas wells . This preference allows a taxpayer to deduct up to 25 percent of the gross income from certain oil and gas wells. The Budget proposal would eliminate this deduction. Cost depletion would continue to be allowed, permitting taxpayers to recover the costs of their wells as the property is exhausted. Elimination of the percentage depletion deduction is projected to raise $10 billion through FY2020.
Domestic manufacturing deduction for oil and gas . This preference allows a taxpayer to deduct up to 6 percent of its income from domestic oil and gas production activities. The Budget proposal would eliminate this deduction. Elimination of the deduction is projected to raise $17.3 billion through FY 2020.
T wo-year amortization of geological and geophysical expenditures . This preference allows non-integrated producers to amortize the cost of certain oil and gas exploration activities over two years (rather than over the seven-year period applicable to integrated oil and gas producers). [1] The Budget proposal would apply the seven-year amortization period to all producers. The change is projected to raise $1.1 billion through FY 2020.

In addition, the Budget proposes to repeal the following tax preferences for coal beginning in 2011:

Expensing of exploration and development costs . This preference allows taxpayers to deduct the costs of exploring for coal deposits and developing mines to exploit the deposit. The Budget proposal would require these costs to be capitalized in accordance with the generally applicable rules. Eliminating this preference is projected to raise $413 million through FY 2020.
Percentage depletion for hard mineral fossil fuels . This preference allows a taxpayer to deduct a percentage of its gross income from hard mineral fossil fuel properties (10 percent in the case of coal). The budget proposal would eliminate this deduction. Cost depletion would continue to be allowed, permitting taxpayers to recover the cost of their mines as the property is exhausted. Elimination of the percentage depletion deduction is projected to raise $1.1 billion through FY 2020.
Capital gains treatment for coal and lignite royalties . This preference provides long-term capital gains treatment for coal and lignite royalties. The budget proposal would eliminate the special rule for coal and lignite royalties. Elimination of the special rule is projected to raise $751 million through 2020.
Domestic manufacturing deduction for coal and other hard mineral fossil fuels . This preference allows a taxpayer to deduct up to 9 percent of its income from domestic coal and other hard mineral fossil fuel activities. The Budget proposal would eliminate this deduction. Elimination of the deduction is projected to raise $57 million through FY 2020.

2. Reinstate Superfund excise taxes.

The Superfund excise taxes, which expired in 1995, included a 9.7-cents-per-barrel excise tax on crude oil and imported petroleum products. To provide a source of funds to remedy damages caused by releases of oil and other hazardous substances, the Budget proposes to reinstate the Superfund excise taxes for the period from 2011 through 2020. Reinstatement of the Superfund excise taxes is projected to raise $7.2 billion through FY 2020.

3. Modify the tax rules for dual capacity taxpayers.

Current U.S. tax rules attempt to identify the portion of a foreign levy paid by a dual-capacity taxpayer that constitutes an income tax eligible for a foreign tax credit versus a payment for a specific economic benefit. In making this determination, current rules place significant weight on the formal characteristics and terms of the foreign levy. In many cases, the terms and the structure of the foreign levy as it applies to U.S. taxpayers have been structured or negotiated to meet, in form, the U.S. requirements of an income tax. The fact that recently certain foreign countries (in particular, Qatar and the United Kingdom) have reduced their statutory corporate income tax rates except with respect to oil and gas companies further indicates that at least a portion of the foreign levies paid by such companies are in fact in exchange for the right to exploit natural resources (that is, a specific economic benefit) and not an income tax. Under the proposal, dual capacity taxpayers will be permitted to claim a credit for the portion of the foreign levy that the taxpayer would pay if it were not a dual capacity taxpayer.

4. Extend expiring provisions.

The Budget proposes to extend through 2011 a number of tax provisions that have either expired or are scheduled to expire before the end of 2011. The following energy incentives are included in the extension proposal:

Incentives for biodiesel and renewable diesel . A $1.00-per-gallon incentive for biodiesel and renewable diesel is provided as an income tax credit, an excise tax credit or a refundable payment. In addition, a $0.10-per-gallon income tax credit is available for small producers. The incentives expired at the end of 2009.
Incentives for alternative fuels . A $0.50-per-gallon (or gasoline gallon equivalent) excise tax credit or refundable payment is provided for alternative fuels such as liquefied hydrogen, natural gas fuels, liquefied petroleum gas, liquid fuels derived from coal, and liquid fuels derived from biomass. The incentives expired at the end of 2009 for fuels other than liquefied hydrogen. The proposed extension would not apply to black liquor.
Incentives for alcohol fuels . A $0.45-per-gallon income tax credit, excise tax credit, or refundable payment is available for alcohol fuels. The incentive is increased to $0.60 per gallon for alcohol other than ethanol and a $0.10-per-gallon credit is available for small producers. The incentives are scheduled to expire at the end of 2010.
Tax credits for alternative fuel refueling property . A 50-percent income tax credit is provided for alternative fuel (including electricity) refueling property, subject to a $50,000 cap for depreciable property and a $2,000 cap for nonbusiness property. The credit rate falls to 30 percent and the caps to $30,000 and $1,000 after 2010. The Budget proposal would delay these reductions for one year.

Tax credits for hybrid automobiles and other alternative motor vehicles . Income tax credits are provided for hybrid vehicles, advanced lean burn technology automobiles, alternative fuel motor vehicles, and fuel cell vehicles. Credits of up to $4,000 are available for passenger automobiles (12,000 for fuel cell vehicles) and of up to $40,000 for heavy motor vehicles. At the end of 2009, the credit for heavy hybrid vehicles expired and the maximum credit for fuel cell vehicles fell to $8,000. The credits expire for other hybrid vehicles, advanced lean burn technology vehicles, and alternative fuel vehicles at the end of 2010. The Budget proposal would extend the credits and the $12,000 maximum credit for fuel cell vehicles through 2011.

Tax credits for energy efficient new homes . A $2,000 dollar income tax credit is allowed for the construction of an energy efficient home ($1,000 in the case of a manufactured home). The credit expired at the end of 2009.
Tax credits for energy efficiency improvements to existing homes . A 30-percent income tax credit is allowed for various energy-efficient home improvements (improvements to the building envelope and the installation of energy-efficient heating and cooling equipment). The aggregate credit is limited to $1,500. The credit expires at the end of 2010.
Tax credits and expensing for low-sulfur diesel fuel refineries . Small refiners are allowed to deduct 75 percent of the cost of modifying a refinery to comply with EPA diesel fuel sulfur control requirements and claim an income tax credit equal to the remaining 25 percent of costs. This treatment is available only for costs incurred before the end of 2009.
Deferral of gain on sales to implement electric restructuring policy . Utilities selling transmission facilities to implement federal or state electric restructuring policy are permitted to report the gain over an 8-year period rather than in the year of sale. This treatment applies only to sales occurring before the end of 2009.
Treatment of natural gas distribution lines as 15-year property . Natural gas lines are treated for cost recovery purposes as 15-year property through the end of 2010 and as 20-year property thereafter. The Budget would extend the treatment as 15-year property through the end of 2011.

5. Provide additional tax credits for advanced energy manufacturing facilities.

As noted above, the Recovery Act provided $2.3 billion in tax credits for investments in advanced energy manufacturing facilities. The credit, under section 48C of the Code, was designed to help America take the lead in the manufacture of wind turbines, solar panels, electric vehicles, and other clean energy and energy conservation products. Eligible manufacturers receive a 30-percent credit for their investments in facilities to manufacture these products.

The Treasury Department and the Department of Energy have cooperated in awarding the $2.3 billion of credits authorized by the Recovery Act. Credits have been awarded to 183 projects in 43 states to support tens of thousands of high quality clean energy jobs and the development of a domestic clean energy manufacturing base.

The $2.3 billion cap on the credit has resulted in the funding of less than one-third of the technically acceptable applications that have been received. The President's FY 2011 Budget proposes an additional $5 billion in credits that would support at least $15 billion in total capital investment, creating tens of thousands of new construction and manufacturing jobs. Because there is already an existing pipeline of worthy projects and substantial interest, the additional credit could be deployed quickly to create jobs and support economic activity.

Conclusion

Mr. Chairman, this concludes my prepared testimony. I will be pleased to answer any questions you or other members of the Committee may have.

APPENDIX: GENERAL EXPLANATIONS OF THE ADMINISTRATION'S FISCAL YEAR 2010 REVENUE PROPOSALS RELATED TO ENERGY

REPEAL ENHANCED OIL RECOVERY CREDIT

Current Law

The general business credit includes a 15-percent credit for eligible costs attributable to enhanced oil recovery (EOR) projects. If the credit is claimed with respect to eligible costs, the taxpayer's deduction (or basis increase) with respect to those costs is reduced by the amount of the credit. Eligible costs include the cost of constructing a gas treatment plant to prepare Alaska natural gas for pipeline transportation and any of the following costs with respect to a qualified EOR project: (1) the cost of depreciable or amortizable tangible property that is an integral part of the project; (2) intangible drilling and development costs (IDCs) that the taxpayer can elect to deduct; and (3) deductible tertiary injectant costs. A qualified EOR project must be located in the United States and must involve the application of one or more of nine listed tertiary recovery methods that can reasonably be expected to result in more than an insignificant increase in the amount of crude oil which ultimately will be recovered. The allowable credit is phased out over a $6 range for a taxable year if the annual average unregulated wellhead price per barrel of domestic crude oil during the calendar year preceding the calendar year in which the taxable year begins (the reference price) exceeds an inflation adjusted threshold. The credit was completely phased out for taxable years beginning in 2009, because the reference price ($94.03) exceeded the inflation adjusted threshold ($42.01) by more than $6.

Reasons for Change

The President agreed at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so that the United States can transition to a 21st century energy economy. The credit, like other oil and gas preferences the Administration proposes to repeal, distorts markets by encouraging more investment in the oil and gas industry than would occur under a neutral system. To the extent the credit encourages overproduction of oil, it is detrimental to long-term energy security and is also inconsistent with the Administration's policy of reducing carbon emissions and encouraging the use of renewable energy sources. Moreover, the credit must ultimately be financed with taxes that result in underinvestment in other, potentially more productive, areas of the economy.

Proposal

The investment tax credit for enhanced oil recovery projects would be repealed for taxable years beginning after December 31, 2010.

REPEAL CREDIT FOR OIL AND GAS PRODUCED FROM MARGINAL WELLS

Current Law

The general business credit includes a credit for crude oil and natural gas produced from marginal wells. The credit rate is $3.00 per barrel of oil and $0.50 per 1,000 cubic feet of natural gas for taxable years beginning in 2005 and is adjusted for inflation in taxable years beginning after 2005. The credit is available for production from wells that produce oil and gas qualifying as marginal production for purposes of the percentage depletion rules or that have average daily production of not more than 25 barrel-of-oil equivalents and produce at least 95 percent water. The credit per well is limited to 1,095 barrels of oil or barrel-of-oil equivalents per year. The credit rate for crude oil is phased out for a taxable year if the annual average unregulated wellhead price per barrel of domestic crude oil during the calendar year preceding the calendar year in which the taxable year begins (the reference price) exceeds the applicable threshold. The phase-out range and the applicable threshold at which phase-out begins are $3.00 and $15.00 for taxable years beginning in 2005 and are adjusted for inflation in taxable years beginning after 2005. The credit rate for natural gas is similarly phased out for a taxable year if the annual average wellhead price for domestic natural gas exceeds the applicable threshold. The phase-out range and the applicable threshold at which phase-out begins are $0.33 and $1.67 for taxable years beginning in 2005 and are adjusted for inflation in taxable years beginning after 2005. The credit has been completely phased out for all taxable years since its enactment. The marginal well credit can be carried back up to five years unlike other components of the general business credit, which can be carried back only one year.

Reasons for Change

Proposal

The production tax credit for oil and gas from marginal wells would be repealed for production in taxable years beginning after December 31, 2010.

REPEAL EXPENSING OF INTANGIBLE DRILLING COSTS

Current Law

In general, costs that benefit future periods must be capitalized and recovered over such periods for income tax purposes, rather than being expensed in the period the costs are incurred. In addition, the uniform capitalization rules require certain direct and indirect costs allocable to property to be included in inventory or capitalized as part of the basis of such property. In general, the uniform capitalization rules apply to real and tangible personal property produced by the taxpayer or acquired for resale.

Special rules apply to intangible drilling and development costs (IDCs). IDCs include all expenditures made by an operator for wages, fuel, repairs, hauling, supplies, and other expenses incident to and necessary for the drilling of wells and the preparation of wells for the production of oil and gas. In addition, IDCs include the cost to operators of any drilling or development work (excluding amounts payable only out of production or gross or net proceeds from production, if the amounts are depletable income to the recipient, and amounts properly allocable to the cost of depreciable property) done by contractors under any form of contract (including a turnkey contract). IDCs include amounts paid for labor, fuel, repairs, hauling, and supplies which are used in the drilling, shooting, and cleaning of wells; in such clearing of ground, draining, road making, surveying, and geological works as are necessary in preparation for the drilling of wells; and in the construction of such derricks, tanks, pipelines, and other physical structures as are necessary for the drilling of wells and the preparation of wells for the production of oil and gas. Generally, IDCs do not include expenses for items which have a salvage value (such as pipes and casings) or items which are part of the acquisition price of an interest in the property.

Under the special rules applicable to IDCs, an operator (i.e., a person who holds a working or operating interest in any tract or parcel of land either as a fee owner or under a lease or any other form of contract granting working or operating rights) who pays or incurs IDCs in the development of an oil or gas property located in the United States may elect either to expense or capitalize those costs. The uniform capitalization rules do not apply to otherwise deductible IDCs.

If a taxpayer elects to expense IDCs, the amount of the IDCs is deductible as an expense in the taxable year the cost is paid or incurred. Generally, IDCs that a taxpayer elects to capitalize may be recovered through depletion or depreciation, as appropriate; or in the case of a nonproductive well ("dry hole"), the operator may elect to deduct the costs. In the case of an integrated oil company (i.e., a company that engages, either directly or through a related enterprise, in substantial retailing or refining activities) that has elected to expense IDCs, 30 percent of the IDCs on productive wells must be capitalized and amortized over a 60-month period.

A taxpayer that has elected to deduct IDCs may, nevertheless, elect to capitalize and amortize certain IDCs over a 60-month period beginning with the month the expenditure was paid or incurred. This rule applies on an expenditure-by-expenditure basis; that is, for any particular taxable year, a taxpayer may deduct some portion of its IDCs and capitalize the rest under this

provision. This allows the taxpayer to reduce or eliminate IDC adjustments or preferences under the alternative minimum tax.

The election to deduct IDCs applies only to those IDCs associated with domestic properties. For this purpose, the United States includes certain wells drilled offshore.

Reasons for Change

The President agreed at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so that the United States can transition to a 21st century energy economy. The expensing of IDCs, like other oil and gas preferences the Administration proposes to repeal, distorts markets by encouraging more investment in the oil and gas industry than would occur under a neutral system. To the extent expensing encourages overproduction of oil and gas, it is detrimental to long-term energy security and is also inconsistent with the Administration's policy of reducing carbon emissions and encouraging the use of renewable energy sources. Moreover, the tax subsidy for oil and gas must ultimately be financed with taxes that result in underinvestment in other, potentially more productive, areas of the economy. Capitalization of IDCs would place the oil and gas industry on a cost recovery system similar to that employed by other industries and reduce economic distortions.

Proposal

Expensing of intangible drilling costs and 60-month amortization of capitalized intangible drilling costs would not be allowed. Intangible drilling costs would be capitalized as depreciable or depletable property, depending on the nature of the cost incurred, in accordance with the generally applicable rules.

The proposal would be effective for costs paid or incurred after December 31, 2010.

REPEAL DEDUCTION FOR TERTIARY INJECTANTS

Current Law

Taxpayers are allowed to deduct the cost of qualified tertiary injectant expenses for the taxable year. Qualified tertiary injectant expenses are amounts paid or incurred for any tertiary injectants (other than recoverable hydrocarbon injectants) that are used as a part of a tertiary recovery method. The deduction is treated as an amortization deduction in determining the amount subject to recapture upon disposition of the property.

Reasons for Change

The President agreed at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so that the United States can transition to a 21st century energy economy. The deduction for tertiary injectants, like other oil and gas preferences the Administration proposes to repeal, distorts markets by encouraging more investment in the oil and gas industry than would occur under a neutral system. To the extent expensing encourages overproduction of oil and gas, it is detrimental to long-term energy security and is also inconsistent with the Administration's policy of reducing carbon emissions and encouraging the use of renewable energy sources. Moreover, the tax subsidy for oil and gas must ultimately be financed with taxes that result in underinvestment in other, potentially more productive, areas of the economy. Capitalization of tertiary injectants would place the oil and gas industry on a cost recovery system similar to that employed by other industries and reduce economic distortions.

Proposal

The deduction for qualified tertiary injectant expenses would not be allowed for amounts paid or incurred after December 31, 2010.

REPEAL EXEMPTION TO PASSIVE LOSS LIMITATION FOR WORKING INTERESTS IN OIL AND GAS PROPERTIES

Current Law

The passive loss rules limit deductions and credits from passive trade or business activities. Deductions attributable to passive activities, to the extent they exceed income from passive activities, generally may not be deducted against other income, such as wages, portfolio income, or business income that is not derived from a passive activity. A similar rule applies to credits. Suspended deductions and credits are carried forward and treated as deductions and credits from passive activities in the next year. The suspended losses and credits from a passive activity are allowed in full when the taxpayer completely disposes of the activity.

Passive activities are defined to include trade or business activities in which the taxpayer does not materially participate. An exception is provided, however, for any working interest in an oil or gas property that the taxpayer holds directly or through an entity that does not limit the liability of the taxpayer with respect to the interest.

Reasons for Change

The President agreed at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so that the United States can transition to a 21st century energy economy. The special tax treatment of working interests in oil and gas properties, like other oil and gas preferences the Administration proposes to repeal, distorts markets by encouraging more investment in the oil and gas industry than would occur under a neutral system. To the extent this special treatment encourages overproduction of oil and gas, it is detrimental to long-term energy security and is also inconsistent with the Administration's policy of reducing carbon emissions and encouraging the use of renewable energy sources. Moreover, the working interest exception for oil and gas must ultimately be financed with taxes that result in underinvestment in other, potentially more productive, areas of the economy. Eliminating the working interest exception would subject oil and gas properties to the same limitations as other activities and reduce economic distortions.

Proposal

The exception from the passive loss rules for working interests in oil and gas properties would be repealed for taxable years beginning after December 31, 2010.

REPEAL PERCENTAGE DEPLETION FOR OIL AND NATURAL GAS WELLS

Current Law

The capital costs of oil and gas wells are recovered through the depletion deduction. Under the cost depletion method, the basis recovery for a taxable year is proportional to the exhaustion of the property during the year. This method does not permit cost recovery deductions that exceed basis or that are allowable on an accelerated basis.

A taxpayer may also qualify for percentage depletion with respect to oil and gas properties. The amount of the deduction is a statutory percentage of the gross income from the property. For oil and gas properties, the percentage ranges from 15 to 25 percent and the deduction may not exceed 100 percent of the taxable income from the property. In addition, the percentage depletion deduction for oil and gas properties may not exceed 65 percent of the taxpayer's overall taxable income (determined before the deduction and with certain other adjustments).

Other limitations and special rules apply to the percentage depletion deduction for oil and gas properties. In general, only independent producers and royalty owners (in contrast to integrated oil companies) qualify for the percentage depletion deduction. In addition, oil and gas producers may claim percentage depletion only with respect to up to 1,000 barrels of average daily production of domestic crude oil or an equivalent amount of domestic natural gas (applied on a combined basis in the case of taxpayers that produce both). This quantity limitation is allocated, at the taxpayer's election, between oil production and gas production and then further allocated within each class among the taxpayer's properties. Special rules apply to oil and gas production from marginal wells (generally, wells for which the average daily production is less than 15 barrels of oil or barrel-of-oil equivalents or that produce only heavy oil). Only marginal well production can qualify for percentage depletion at a rate of more than 15 percent. The rate is increased in a taxable year that begins in a calendar year following a calendar year during which the annual average unregulated wellhead price per barrel of domestic crude oil is less than $20. The increase is one percentage point for each whole dollar of difference between the two amounts. In addition, marginal wells are exempt from the 100-percent-of-net-income limitation described above in taxable years beginning during the period 1998-2007 and in taxable years beginning in 2009. Unless the taxpayer elects otherwise, marginal well production is given priority over other production in applying the 1,000-barrel limitation on percentage depletion.

A qualifying taxpayer determines the depletion deduction for each oil and gas property under both the percentage depletion method and the cost depletion method and deducts the larger of the two amounts. Because percentage depletion is computed without regard to the taxpayer's basis in the depletable property, a taxpayer may continue to claim percentage depletion after all the expenditures incurred to acquire and develop the property have been recovered.

Reasons for Change

The President agreed at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so that the United States can transition to a 21st century energy economy. Percentage depletion effectively provides a lower rate of tax with respect to a favored source of income. The lower rate of tax, like other oil and gas preferences the Administration proposes to repeal, distorts markets by encouraging more investment in the oil and gas industry than would occur under a neutral system. To the extent the lower tax rate encourages overproduction of oil and gas, it is detrimental to long-term energy security and is also inconsistent with the Administration's policy of reducing carbon emissions and encouraging the use of renewable energy sources. Moreover, the tax subsidy for oil and gas must ultimately be financed with taxes that result in underinvestment in other, potentially more productive, areas of the economy.

Cost depletion computed by reference to the taxpayer's basis in the property is the equivalent of economic depreciation. Limiting oil and gas producers to cost depletion would place them on a cost recovery system similar to that employed by other industries and reduce economic distortions.

Proposal

Percentage depletion would not be allowed with respect to oil and gas wells. Taxpayers would be permitted to claim cost depletion on their adjusted basis, if any, in oil and gas wells.

The proposal would be effective for taxable years beginning after December 31, 2010.

REPEAL DOMESTIC MANUFACTURING DEDUCTION FOR OIL AND GAS PRODUCTION

Current Law

A deduction is allowed with respect to income attributable to domestic production activities (the manufacturing deduction). For taxable years beginning after 2009, the manufacturing deduction is generally equal to 9 percent of the lesser of qualified production activities income for the taxable year or taxable income for the taxable year, limited to 50 percent of the W-2 wages of the taxpayer for the taxable year. The deduction for income from oil and gas production activities is computed at a 6 percent rate.

Qualified production activities income is generally calculated as a taxpayer's domestic production gross receipts (i.e., the gross receipts derived from any lease, rental, license, sale, exchange, or other disposition of qualifying production property manufactured, produced, grown, or extracted by the taxpayer in whole or significant part within the United States; any qualified film produced by the taxpayer; or electricity, natural gas, or potable water produced by the taxpayer in the United States) minus the cost of goods sold and other expenses, losses, or deductions attributable to such receipts.

The manufacturing deduction generally is available to all taxpayers that generate qualified production activities income, which under current law includes income from the sale, exchange or disposition of oil, natural gas or primary products thereof produced in the United States.

Reasons for Change

The President agreed at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so that the United States can transition to a 21st century energy economy. The manufacturing deduction effectively provides a lower rate of tax with respect to a favored source of income. The lower rate of tax, like other oil and gas preferences the Administration proposes to repeal, distorts markets by encouraging more investment in the oil and gas industry than would occur under a neutral system. To the extent the lower tax rate encourages overproduction of oil and gas, it is detrimental to long-term energy security and is also inconsistent with the Administration's policy of reducing carbon emissions and encouraging the use of renewable energy sources. Moreover, the tax subsidy for oil and gas must ultimately be financed with taxes that result in underinvestment in other, potentially more productive, areas of the economy.

Proposal

The proposal would exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange or other disposition of oil, natural gas or a primary product thereof for taxable years beginning after December 31, 2010.

INCREASE GEOLOGICAL AND GEOPHYSICAL AMORTIZATION PERIOD FOR INDEPENDENT PRODUCERS TO SEVEN YEARS

Current Law

Geological and geophysical expenditures are costs incurred for the purpose of obtaining and accumulating data that will serve as the basis for the acquisition and retention of mineral properties. The amortization period for geological and geophysical expenditures incurred in connection with oil and gas exploration in the United States is two years for independent producers and seven years for integrated oil and gas producers.

Reasons for Change

The President agreed at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so that the United States can transition to a 21st century energy economy. The accelerated amortization of geological and geophysical expenditures incurred by independent producers, like other oil and gas preferences the Administration proposes to repeal, distorts markets by encouraging more investment in the oil and gas industry than would occur under a neutral system. To the extent accelerated amortization encourages overproduction of oil and gas, it is detrimental to long-term energy security and is also inconsistent with the Administration's policy of reducing carbon emissions and encouraging the use of renewable energy sources. Moreover, the tax subsidy for oil and gas must ultimately be financed with taxes that result in underinvestment in other, potentially more productive, areas of the economy.

Increasing the amortization period for geological and geophysical expenditures incurred by independent oil and gas producers from two years to seven years would provide a more accurate reflection of their income and more consistent tax treatment for all oil and gas producers.

Proposal

The proposal would increase the amortization period from two years to seven years for geological and geophysical expenditures incurred by independent producers in connection with all oil and gas exploration in the United States. Seven-year amortization would apply even if the property is abandoned and any remaining basis of the abandoned property would be recovered over the remainder of the seven-year period. The proposal would be effective for amounts paid or incurred after December 31, 2010.

REPEAL EXPENSING OF EXPLORATION AND DEVELOPMENT COSTS

Current Law

Special rules apply in the case of mining exploration and development expenditures. A taxpayer may elect to expense the exploration costs incurred for the purpose of ascertaining the existence, location, extent, or quality of an ore or mineral deposit, including a deposit of coal or other hard mineral fossil fuel. Exploration costs that are expensed are recaptured when the mine reaches the producing stage either by a reduction in depletion deductions or, at the election of the taxpayer, by an inclusion in income in the year in which the mine reaches the producing stage.

After the existence of a commercially marketable deposit has been disclosed, costs incurred for the development of a mine to exploit the deposit are deductible in the year paid or incurred unless the taxpayer elects to deduct the costs on a ratable basis as the minerals or ores produced from the deposit are sold.

In the case of a corporation that elects to deduct exploration costs in the year paid or incurred, 30 percent of the otherwise deductible costs must be capitalized and amortized over a 60-month period. In addition, a taxpayer that has elected to deduct exploration costs may, nevertheless, elect to capitalize and amortize certain intangible drilling costs over a 60-month period beginning with the month the expenditure was paid or incurred. This rule applies on an expenditure-by-expenditure basis; that is, for any particular taxable year, a taxpayer may deduct some portion of its exploration costs and capitalize the rest under this provision. This allows the taxpayer to reduce or eliminate adjustments or preferences for exploration costs under the alternative minimum tax. Similar rules limiting corporate deductions and providing for 60-month amortization apply with respect to mine development costs.

The election to deduct exploration costs and the rule making development costs deductible in the year paid or incurred apply only with respect to domestic ore and mineral deposits.

Reasons for Change

The President agreed at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so that the United States can transition to a 21st century energy economy. The expensing of exploration and development costs relating to coal and other hard mineral fossil fuels, like other fossil fuel preferences the Administration proposes to repeal, distorts markets by encouraging more investment in fossil fuel production than would occur under a neutral system. To the

extent expensing encourages overproduction of coal and other hard mineral fossil fuels, it is inconsistent with the Administration's policy of reducing carbon emissions and encouraging the use of renewable energy sources. Moreover, the tax subsidy for coal and other hard mineral fossil fuels must ultimately be financed with taxes that result in underinvestment in other, potentially more productive, areas of the economy. Capitalization of exploration and development costs relating to coal and other hard mineral fossil fuels would place taxpayers in that industry on a cost recovery system similar to that employed by other industries and reduce economic distortions.

Proposal

Expensing and 60-month amortization of exploration and development costs relating to coal and other hard mineral fossil fuels would not be allowed. The costs would be capitalized as depreciable or depletable property, depending on the nature of the cost incurred, in accordance with the generally applicable rules. The other hard mineral fossil fuels for which expensing and 60-month amortization would not be allowed include lignite and oil shale to which a 15-percent depletion rate applies.

The proposal would be effective for costs paid or incurred after December 31, 2010.

REPEAL PERCENTAGE DEPLETION FOR HARD MINERAL FOSSIL FUELS

Current Law

The capital costs of coal mines and other hard mineral fossil fuel properties are recovered through the depletion deduction. Under the cost depletion method, the basis recovery for a taxable year is proportional to the exhaustion of the property during the year. This method does not permit cost recovery deductions that exceed basis or that are allowable on an accelerated basis.

A taxpayer may also qualify for percentage depletion with respect to coal and other hard mineral fossil fuel properties. The amount of the deduction is a statutory percentage of the gross income from the property. The percentage is 10 percent for coal and lignite and 15 percent for oil shale (other than oil shale to which a 7 ½ percent depletion rate applies because it is used for certain nonfuel purposes). The deduction may not exceed 50 percent of the taxable income from the property (determined before the deductions for depletion and domestic manufacturing).

Reasons for Change

The President agreed at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so that the United States can transition to a 21st century energy economy. Percentage depletion effectively provides a lower rate of tax with respect to a favored source of income. The lower rate of tax, like other fossil fuel preferences the Administration proposes to repeal, distorts markets by encouraging more investment in fossil fuel production than would occur under a neutral system. To the extent the lower tax rate encourages overproduction of coal and other hard mineral fossil fuels, it is inconsistent with the Administration's policy of reducing carbon emissions and encouraging the use of renewable energy sources. Moreover, the tax subsidy for coal and other hard mineral fossil fuels must ultimately be financed with taxes that result in underinvestment in other, potentially more productive, areas of the economy.

Cost depletion computed by reference to the taxpayer's basis in the property is the equivalent of economic depreciation. Limiting fossil fuel producers to cost depletion would place them on a cost recovery system similar to that employed by other industries and reduce economic distortions.

Proposal

Percentage depletion would not be allowed with respect to coal and other hard mineral fossil fuels. The other hard mineral fossil fuels for which no percentage depletion would be allowed include lignite and oil shale to which a 15-percent depletion rate applies. Taxpayers would be

permitted to claim cost depletion on their adjusted basis, if any, in coal and other hard mineral fossil fuel properties.

The proposal would be effective for taxable years beginning after December 31, 2010.

REPEAL CAPITAL GAINS TREATMENT OF CERTAIN ROYALTIES

Current Law

Royalties received on the disposition of coal or lignite generally qualify for treatment as long-term capital gain, and the royalty owner does not qualify for percentage depletion with respect to the coal or lignite. This treatment does not apply unless the taxpayer has been the owner of the mineral in place for at least one year before it is mined. The treatment also does not apply to income realized as a co-adventurer, partner, or principal in the mining of the mineral or to certain related party transactions.

Reasons for Change

The President agreed at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so that the United States can transition to a 21st century energy economy. The capital gain treatment of coal and lignite royalties, like other fossil fuel preferences the Administration proposes to repeal, distorts markets by encouraging more investment in fossil fuel production than would occur under a neutral system. To the extent capital gains treatment encourages overproduction of coal and lignite, it is inconsistent with the Administration's policy of reducing carbon emissions and encouraging the use of renewable energy sources. Moreover, the tax subsidy for coal and lignite must ultimately be financed with taxes that result in underinvestment in other, potentially more productive, areas of the economy.

Proposal

The capital gain treatment of coal and lignite royalties would be repealed and the royalties would be taxed as ordinary income.

The proposal would be effective for amounts realized in taxable years beginning after December 31, 2010.

REPEAL DOMESTIC MANUFACTURING DEDUCTION FOR COAL AND OTHER HARD MINERAL FOSSIL FUELS

Current Law

The manufacturing deduction generally is available to all taxpayers that generate qualified production activities income, which under current law includes income from the sale, exchange or disposition of coal, other hard mineral fossil fuels, or primary products thereof produced in the United States.

Reasons for Change

The President agreed at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so that the United States can transition to a 21st century energy economy. The manufacturing deduction effectively provides a lower rate of tax with respect to a favored source of income. The lower rate of tax, like other fossil fuel preferences the Administration proposes to repeal, distorts markets by encouraging more investment in fossil fuel production than would occur under a neutral system. To the extent the lower tax rate encourages overproduction of coal and other hard mineral fossil fuels, it is inconsistent with the Administration's policy of reducing carbon emissions and encouraging the use of renewable energy sources. Moreover, the tax subsidy for coal and other hard mineral fossil fuels must ultimately be financed with taxes that result in underinvestment in other, potentially more productive, areas of the economy.

Proposal

The proposal would exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange or other disposition of coal, other hard mineral fossil fuels, or a primary product thereof. The hard mineral fossil fuels to which the exclusion would apply include lignite and oil shale to which a 15-percent depletion rate applies.

The proposal would be effective for taxable years beginning after December 31, 2010.

REINSTATE SUPERFUND EXCISE TAXES

Current Law

The following Superfund excise taxes were imposed before January 1, 1996:

(1) An excise tax on domestic crude oil and on imported petroleum products at a rate of $0.097 per barrel;

(2) An excise tax on listed hazardous chemicals at a rate that varied from $0.22 to $4.87 per ton; and

(3) An excise tax on imported substances that use as materials in their manufacture or production one or more of the hazardous chemicals subject to the excise tax described in (2) above.

Amounts equivalent to the revenues from these taxes were dedicated to the Hazardous Substance Superfund Trust Fund (the Superfund Trust Fund). Amounts in the Superfund Trust Fund are available for expenditures incurred in connection with releases or threats of releases of hazardous substances into the environment under specified provisions of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (as amended).

Reasons for Change

The Superfund excise taxes should be reinstated because of the continuing need for funds to remedy damages caused by releases of hazardous substances.

Proposal

The three Superfund excise taxes would be reinstated for periods after December 31, 2010. The taxes would sunset after December 31, 2020.

MODIFY THE TAX RULES FOR DUAL CAPACITY TAXPAYERS

Current Law

Section 901 provides that, subject to certain limitations, a taxpayer may choose to claim a credit against its U.S. income tax liability for income, war profits, and excess profits taxes paid or accrued during the taxable year to any foreign country or any possession of the United States. To be a creditable tax, a foreign levy must be substantially equivalent to an income tax under United States tax principles, regardless of the label attached to the levy under law. Under current Treasury regulations, a foreign levy is a tax if it is a compulsory payment under the authority of a foreign government to levy taxes and is not compensation for a specific economic benefit provided by the foreign country. Taxpayers that are subject to a foreign levy and that also receive a specific economic benefit from the levying country (dual capacity taxpayers) may not credit the portion of the foreign levy paid for the specific economic benefit. The current Treasury regulations provide that, if a foreign country has a generally-imposed income tax, the dual capacity taxpayer may treat as a creditable tax the portion of the levy that application of the generally imposed income tax would yield (provided that the levy otherwise constitutes an income tax or an in lieu of tax). The balance of the levy is treated as compensation for the specific economic benefit. If the foreign country does not generally impose an income tax, the portion of the payment that does not exceed the applicable federal tax rate applied to net income is treated as a creditable tax. A foreign tax is treated as generally imposed even if it applies only to persons who are not residents or nationals of that country.

There is no separate section 904 foreign tax credit basket for oil and gas income. However, under section 907, the amount of creditable foreign taxes imposed on foreign oil and gas income is limited in any year to the applicable U.S. tax on that income.

Reasons for Change

The purpose of the foreign tax credit is to mitigate double taxation of income by the United States and a foreign country. When a payment is made to a foreign country in exchange for a specific economic benefit, there is no double taxation. Current law recognizes the distinction between a payment of creditable taxes and a payment in exchange for a specific economic benefit but fails to achieve the appropriate split between the two when a single payment is made in a case where, for example, a foreign country imposes a levy only on oil and gas income, or imposes a higher levy on oil and gas income as compared to other income.

Proposal

In the case of a dual capacity taxpayer, the proposal would allow the taxpayer to treat as a creditable tax the portion of a foreign levy that does not exceed the foreign levy that the taxpayer would pay if it were not a dual-capacity taxpayer. The proposal would replace the current regulatory provisions, including the safe harbor, that apply to determine the amount of a foreign levy paid by a dual-capacity taxpayer that qualifies as a creditable tax. The proposal also would convert the special foreign tax credit limitation rules of section 907 into a separate category within section 904 for foreign oil and gas income. The proposal would yield to United States

treaty obligations to the extent that they allow a credit for taxes paid or accrued on certain oil or gas income.

The proposal would be effective for taxable years beginning after December 31, 2010

CONTINUE CERTAIN EXPIRING PROVISIONS THROUGH CALENDAR YEAR 2011

A number of temporary tax provisions are scheduled to expire before December 31, 2011. The Administration proposes to extend a number of these provisions through December 31, 2011. These provisions include the optional deduction for State and local general sales taxes, the Subpart F "active financing" and "look-through" exceptions, the exclusion from unrelated business income of certain payments to controlling exempt organizations, the modified recovery period for qualified leasehold improvements and qualified restaurant property, incentives for empowerment and community renewal zones, and several trade agreements, including the Generalized System of Preferences and the Caribbean Basin Initiative. In accordance with the President's agreement at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels, temporary incentives provided for the production of fossil fuels would be allowed to expire as scheduled under current law.

PROVIDE ADDITIONAL TAX CREDITS FOR INVESTMENT IN QUALIFIED PROPERTY USED IN A QUALIFYING ADVANCED ENERGY MANUFACTURING PROJECT

Current Law

A 30-percent tax credit is provided for investments in eligible property used in a qualifying advanced energy project. A qualifying advanced energy project is a project that re-equips, expands, or establishes a manufacturing facility for the production of: (1) property designed to produce energy from renewable resources; (2) fuel cells, microturbines, or an energy storage system for use with electric or hybrid-electric vehicles; (3) electric grids to support the transmission, including storage, of intermittent sources of renewable energy; (4) property designed to capture and sequester carbon dioxide emissions; (5) property designed to refine or blend renewable fuels or to produce energy conservation technologies; (6) electric drive motor vehicles that qualify for tax credits or components designed for use with such vehicles; and (7) other advanced energy property designed to reduce greenhouse gas emissions.

Eligible property is property: (1) that is necessary for the production of the property listed above; (2) that is tangible personal property or other tangible property (not including a building and its structural components) that is used as an integral part of a qualifying facility; and (3) with respect to which depreciation (or amortization in lieu of depreciation) is allowable.

Total credits are limited to $2.3 billion, and the Treasury Department, in consultation with the Department of Energy, was required to establish a program to consider and award certifications for qualified investments eligible for credits within 180 days of the date of enactment of the American Recovery and Reinvestment Act of 2009. Credits may be allocated only to projects where there is a reasonable expectation of commercial viability. In addition, consideration must be given to which projects: (1) will provide the greatest domestic job creation; (2) will have the greatest net impact in avoiding or reducing air pollutants or greenhouse gas emissions; (3) have the greatest potential for technological innovation and commercial deployment; (4) have the lowest levelized cost of generated or stored energy, or of measured reduction in energy consumption or greenhouse gas emission; and (5) have the shortest completion time. Guidance under current law requires taxpayers to apply for the credit with respect to their entire qualified investment in a project.

Applications for certification under the program may be made only during the two-year period beginning on the date the program is established. An applicant that is allocated credits must provide evidence that the requirements of the certification have been met within one year of the date of acceptance of the application and must place the property in service within three years from the date of the issuance of the certification.

Reasons for Change

The $2.3 billion cap on the credit has resulted in the funding of less than one-third of the technically acceptable applications that have been received. Instead of turning down worthy applicants who are willing to invest private resources to build and equip factories that manufacture clean energy products in America, the program should be expanded. An additional $5 billion in credits would support at least $15 billion in total capital investment, creating tens of thousands of new construction and manufacturing jobs. Because there is already an existing pipeline of worthy projects and substantial interest in this area, the additional credit can be deployed quickly to create jobs and support economic activity.

Proposal

The proposal would authorize an additional $5 billion of credits for investments in eligible property used in a qualifying advanced energy project. The guidance that requires taxpayers to apply for the credit with respect to their entire qualified investment will be modified so that taxpayers can apply for a credit with respect to only part of their qualified investment. If a taxpayer applies for a credit with respect to only part of the qualified investment in the project, the taxpayer's increased cost sharing and the project's reduced revenue cost to the government will be taken into account in determining whether to allocate credits to the project.

Applications for the additional credits would be made during the two-year period beginning on the date on which the additional authorization is enacted. As under current law, applicants that are allocated the additional credits must provide evidence that the requirements of the certification have been met within one year of the date of acceptance of the application and must place the property in service within three years from the date of the issuance of the certification.

The change would be effective on the date of enactment.

[1] A non-integrated company is one that receives nearly all of its revenues from production at the wellhead. The definition contained in the IRS code is that a firm is non-integrated if its refining capacity is less than 50,000 barrels per day on any given day or their retail sales are less than $5 million for the year.

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Statement of Michael F. Mundaca Assistant Secretary (Tax Policy) Department of the Treasury Before Committee on Ways and Means April 14, 2010